Technical Field
The present invention relates to a well-bore monitoring process involving logging the temperature and resistivity of a soil, rock, and brine mixture in a carbonate rock formation continuously to identify the formation of scale.
Description of the Related Art
The “background” description provided herein is for the purpose of generally presenting the context of the disclosure. Work of the presently named inventors, to the extent it is described in this background section, as well as aspects of the description which may not otherwise qualify as prior art at the time of filing, are neither expressly or impliedly admitted as prior art against the present invention.
A common production or injection problem in CO2 sequestration projects is scale formation in reservoirs and around injection and production wells, which hampers formation injectivity and productivity. Scales plug formation pores, throats and well perforations. Scales also deposit on downhole pumps, tubings, casing, flowlines, valves, separators, and many other production facilities. Scales are formed as a result of depressurization, or reaction of formation fluids. See Smith, J. K., Yuan, M., Lopez, T. H., Means, M., and Przbylinski, J. L., 2004, “Real-time and in situ detection of Calcium carbonate scale in a west Texas oil field,” SPE Production & Facilities, May, pp. 94-99, incorporated herein by reference in its entirety. Common oil field scales include calcium carbonate, calcium sulfate, barium sulfates, and strontium sulfate.
Temperature, pressure, and pH variation, are the driving forces for oil field scale formation. Several scale management techniques exist, such as chemical treatment. Chemical treatment involves injection of scale inhibitors, such as chelating agents, inorganic phosphates, and phosphonates into formation water at concentrations high enough to prevent scale formation. Frequent and continuous geochemical analysis of produced formation water and petrographic analysis of cuttings for the purpose of monitoring the presence of scaling ions is another part of scale management. Such analyses allow surface engineers to detect when and where scale inhibitors will have an optimal effect. The use of computer models to predict scaling tendency is also common but does not replace empirical monitoring processes. Sources of concern with these methods include high cost, possible unsuccessful inhibition strategy, and susceptibility of surface analysis to errors. Other problems include compositional change with time of produced fluid caused by evolution of dissolved gases (e.g. CO2), scale precipitation, co-precipitation of scaling ions with suspended solids, and microbial actions. Hence, computer modeling does not effectively capture the dynamics of produced water chemistry. Other field tested online techniques have been reported in the literature namely: ultrasonic (See Gunarathne, G. P. P., and Keatch, R. W., 1995, “Novel technique for monitoring and enhancing dissolution of dissolution of mineral deposits in petroleum pipelines”, Paper SPE 30418 presented at the SPE offshore Europe Conference, Aberdeen, 5-8 September, incorporated herein by reference in its entirety), pulsed spectral gamma logs (See Wyatt, D. F., Jacobson, L. A., and Fox, P., 1994, “Use of supplemental curves from pulsed spectral gamma logs to enhance log interpretation,” Paper SPE 28410 presented at the SPE annual technical conference and exhibition, New Orleans, 25-28 September, incorporated herein by reference in its entirety), dual energy venture multiphase flow measurements (See Theuveny, B. et al. 2001, “Detection and identification of scales using dual energy/venture subsea or topside multiphase meters,” Paper OTC 13152 presented at the 2001 Offshore Technology Conference, Houston, 30 April-3 May, incorporated herein by reference in its entirety), gamma ray attenuation (See Bamforth, S. et al., 1996, “Revitalizing Production Logging,” Oil field review, 8 (4), pp. 44-60, incorporated herein by reference in its entirety), and attenuated total reflectance. Some real-time monitoring techniques have also been tested in the laboratory such as rotating disc electrode (See Morizot, A. P. and Neville, A. 2000, “A novel Approach for monitoring of CaCO3 and BaSO4 scale formation,” Paper SPE 60189 presented at the 2000 SPE second International Symposium on Oilfield Scale, Aberdeen, 26-27 January, incorporated herein by reference in its entirety), tapered optical fiber, and near real-time sensors (See Emmons, D. H. et al., 1999, “Onsite, Near-Real-Time Monitoring of Scale Deposition,” Paper SPE 56776 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Houston, 3-6 October, incorporated herein by reference in its entirety).
The cost of intervention and the cost of production loss during periodic reservoir measurements can be extremely high. Simple intervention in a single well can be as high as $2 million and more than $5 million for wireline logging in subsea wells of water depth in excess of 1500 m (See Al-Asimi, M., Butler G., Brown, G. et al., 2002/2003, “Advances in Well and Reservoir Surveillance,” Oilfield Review, winter, pp. 14-35, incorporated herein by reference in its entirety). In recent times, permanent monitoring sensors are installed down hole near sandface during well completion for constant reservoir surveillance of reservoir fluid. Data can be delivered continuously or on demand thereby avoiding intervention cost. Data acquisition frequency can be as high as a fraction of a second and at every meter. Examples of data measured include pressure, temperature, flow rate, fluid phase, and resistivity. Also permanent sensors have been used to monitor working environment of downhole pumps such as motor temperature, vibration, and current leakage. Constant reservoir and well surveillance can help detect potential problems, predict future reservoir and well performance, and also in timely decisions and corrective actions such as adjusting production parameters and scheduling workover operations. Many decades of experience with downhole sensors have brought about innovative methods and technologies that ensure effective data transmission and handling, and longer sensor life. One service company recorded 75 years of continuous measurement of permanent downhole sensors with only one recorded failure. Furthermore, combined tech based reservoir monitoring techniques such as combined resistivity and time lapse (4D) seismic have been utilized to observe changes in reservoirs around injection and production wells which is helpful in detecting and mitigating potential production problems.
The use of temperature logs for monitoring fluid entry or production from oil and gas wells is an old practice. As fluid is injected or produced from a well, the temperature profile changes from the geothermal gradient. Cooling effects (Joule Thomson effect) occurs due to formation gas expansion as they enter the well-bore from the reservoir while warming effects occur during oil and water entry into wells. Temperature log is therefore used to detect location and time of premature fluid entry, early water breakthrough, leakages in well completion, and other production problems. In artificial lift operations, downhole pump environments (temperature, vibration and current leakages) are continuously monitored and adjusted for optimal performance. Pump optimization will ensure longer pump life, reduced intervention and pump replacement cost. Improved practice involves advanced technologies that allow safe deployment and efficient transmission of quality data such that small changes in temperature can be accounted for. Advanced use of temperature logs for well surveillance is reported in a field in Oman, where a distributed temperature system (DTS) is installed downhole to transmit temperature profiles of the production interval of a horizontal well. An important feature of this log is the sensitivity to small temperature change lower than ±0.4° C. A DTS temperature resolution of 0.001° C. has been reported in the literature (See Suárez, F., Aravena, J. E., Hausner, M. B., Childress, A. E., Tyler, S. W., 2011, “Assessment of a vertical high-resolution distributed-temperature-sensing system in a shallow thermohaline environment”, Hydrol. Earth Syst. Sci. 15 (3), pp. 1081-1093, incorporated herein by reference in their entirety).
Resistivity logs have also been used in the horizontal sections of a well in another field (Lamott field in Indiana, USA) to monitor fluid movement in a reservoir. In this case, centralizers spaced 20 ft apart were used as the electrodes. Current was applied at one end of the electrode and received at the surface. The voltage drop across each electrode divided by the current through it is a measure of the formation resistance at the corresponding electrode location. The resistivity array identified water migration due to production from a particular zone. Resistivity changes lower than 0.05 ohm-meters were captured by the sensors and provided meaningful information about reservoir fluid migration.
Electrical resistivity of rocks depends on: water saturation; type of ions and ionic strength; temperature; and cation exchange capacity. As a result, high resolution electrical resistance tomography has been successfully used to monitor subsurface migration of various fluids and contaminants, leakage detection, and monitoring of cap rock integrity (See Ramirez, A., Daily, W., Binley, A., LaBrecque, D., and Roelant, D., 1996, “Detection of leaks in underground storage tanks using electrical resistance methods,” Journal of Environmental and Engineering Geophysics, 1 (3), pp. 189-203; See Daily, W., and Ramirez, A., 2000, “Electrical imaging of engineered hydraulic barriers,” Geophysics, 65 (1), pp. 83-94; and See Newmark, R. L., Daily, W., and Ramirez, A., 2000, “Electrical Imaging EOR stimulation using steel-cased boreholes,” Paper SPE 62567 presented at the SPE/AAPG Western Regional Meeting, Long Beach, Calif. June 19-23 (references), each incorporated herein by reference in their entirety). During CO2 sequestration, current industry practice is to log resistivity as a function of depth in many observation wells drilled around an injection well and in strategic locations across the reservoir. The objectives of such logs include: evaluation of reservoir performance, detection of leaks and flow path, and understanding geophysical and geochemical interaction of CO2 with rock and rock fluids.
Other previous works have focused on the applicability of electrical resistivity measurements to track carbon dioxide (CO2) migration by way of resistivity change as a function of CO2 saturation changes during CO2 sequestration. Others have also studied the effect of CO2 injection on the petro-physical and electrical properties of rocks using a continual flow of fluid in and out of the sample, with such flow experiments lasting for few hours or less (See Ramirez, A. L., Newmark, R. L., and Daily, W. D., 2003, “Monitoring Carbon dioxide Floods using Electrical Resistance Tomography ERT: Sensitivity Studies,” Journal of Environmental and Engineering Geophysics, 8, pp. 187-208; See Seo, J. G. and Mamora, D. D., 2005, “Experimental and Simulation Studies of Sequestration of Supercritical Carbon Dioxide in Depleted Gas Reservoirs,” Journal of Energy Resources Technology 127(1), pp. 1-6; See Christensen, N. B., Sherlock, D., and Dodds, K., 2006, “Monitoring CO2 Injection with Cross hole Electrical Resistivity Tomography,” Exploration Geophysics, 37, pp. 44-49; See Nogueira, M. and Mamora, D. D., 2008, “Effect of Flue-Gas Impurities on the Process of Injection and Storage of CO2 in Depleted Gas Reservoirs,” Journal of Energy Resources Technology, 130(1), 013301-013301: DOI:10.1115/1.2825174; See Nakatsuka, Y., Xue, Z., Garcia, H., et al., 2010, “Experimental study on CO2 monitoring and quantification of stored CO2 in saline formations using resistivity measurements,” International Journal of Greenhouse Gas Control, 4, pp. 209-216; See Wang, S., and Jaffe, P. R., 2004, “Dissolution of a mineral phase in potable aquifers due to CO2 releases from deep formations; effect of dissolution kinetics,” Energy Conversion and Management, 45, pp. 2833-2848; See Mohamed, I. M., He, J., et al., 2012, “Experimental Analysis of CO2 Injection on Permeability of Vuggy Carbonate Aquifers,” Journal of Energy Resources Technology 135(1): 013301-013301; and See Nguyen, P., H. Fadaei, et al., 2013, “Microfluidics Underground: A Micro-Core Method for Pore Scale Analysis of Supercritical CO2 Reactive Transport in Saline Aquifers,” Journal of Fluids Engineering, 135(2), 021203-021203, each incorporated herein by reference in their entirety). These studies did not consider what happens with formation resistivity after a longer experimental period.
In view of the forgoing, the objective of the present disclosure is to provide a well-bore monitoring process involving logging the temperature and resistivity of a soil, rock, and brine mixture in a carbonate rock formation continuously to identify the formation of scale.